The present invention is concerned with the capturing of acid compounds, such as carbon dioxide, from high pressure acid gasses, which is significantly different from the removal of carbon dioxide from flue gasses originating from the combustion of fossil fuels, such as for alleviating the greenhouse effect and addressing the global warming concerns associated with an increasing CO2 content in the earth's atmosphere. There are major differences in the problems to be solved between the removal of CO2 from flue gasses at about atmospheric pressures, and the deacidification of process streams, which are typically at pressures significantly higher than atmospheric. The particular problem with the deacidification of flue gasses is associated with the presence of oxygen, sulphur oxides and nitrogen oxides, and possibly even hydrogen chloride, HCl. Most absorbents will degrade relatively fast in the presence of oxygen. Sulphur oxides, nitrogen oxides and HCl will irreversibly react with most absorbents and form salts which are lost for the absorption. For instance EP 2036602 A1 is primarily concerned with the removal of CO2 at approximately atmospheric pressure and a concentration of 10%, typical for flue gasses from fossil fuels.
The deacidification of process streams is sometimes also known as “sweetening”, in particular when it concerns the removal of sulphur containing acid compounds such as H2S and/or mercaptans.
A wide variety of process streams containing acid compounds exists which are at above atmospheric pressures and from which it is desirable to remove at least part of the acid compounds in order to eliminate or reduce the problems which these acid compounds may cause downstream, and/or in order to recover the acid compounds for further use.
The acid compounds of concern for the present invention are hydrogen sulphide, H2S, carbon dioxide, CO2, carbon oxysulphide, COS, carbon disulphide, CS2, disulphides and mercaptans.
Such process streams occur for example in the winning of natural gas. The gas from natural gas fields may contain significant amounts of carbon dioxide, readily up to 70% volume. Carbon dioxide and other acid compounds may therefore need to be removed in order to reduce further transportation costs as compressed gas, to mitigate risk of corrosion in downstream systems and pipelines, to adjust the heating value of the gas in order to suit the consumer needs, and/or to enable the liquefaction of the natural gas into liquefied natural gas, LNG, a means of transport of increasing use to bring natural gas from a remote winning location to the gas consumption market.
The removal of H2S and other sulphur containing compounds such as carbon oxysulphide, carbon disulphide and other disulphides, and mercaptans, may be important in an even much wider variety of circumstances. Acid rain concerns for example have continued to increase the pressure on further reducing the sulphur content of all combustion fuels, including gasses as well as liquids.
Acid compound removal may also be important in the production of synthesis gas, consisting primarily of H2, CO and possibly also N2, a gas which is in various forms an important chemical building block but also an important intermediate in the conversion of energy from solid carbon containing streams, such as solid waste streams, tar sands, oil shale and the like. It is usually desirable to remove CO2 and if present also H2S from the synthesis gas, because the CO2 may for instance act as a disturbing inert in the downstream process, and the H2S may be an undesirable reactant therein and/or lead to emission of sulphur oxides (SOx) upon combustion, undesirable in view of the acid rain concerns.
Acid compound removal is also important in the context of the refinery of petroleum. Refinery streams such as the liquefied petroleum gas (LPG) fraction, the offgasses from fluid catalytic cracking (FCC), the hydrotreater offgasses, and the refinery gas usually contain significant amounts of H2S and/or mercaptans, and in some also CO2 may be present. The distillation fractions intended for the different fuel pools need to be desulphurized in order to alleviate the acid rain problem caused by SOx-emissions in the flue gas after combustion. Several of these liquid fractions are therefore subjected to hydrodesulphurization, a refinery step which converts the heavier sulphur compounds into gaseous H2S. In a so-called Claus plant, the H2S which is collected from all these sources may then be converted into elemental sulphur, which has become a product of commerce, for instance as feedstock for the production of sulphuric acid.
The removal of acid compounds from gasses, and to a lesser extent also from organic liquids such as for instance LPG streams, is typically performed by washing the stream with an absorbent solution, usually at a relatively low temperature in order to favour the absorption of the acid compound. The absorbent solution contains absorbents of a basic nature, and amine compounds have been preferred over alternatives such as hot potassium carbonate. Even more preferred were alkanol amines. A conventional absorbent is for instance 2-hydroxyethyl amine, also known as monoethanol amine (MEA). The acid compounds absorbed react with the alkanolamine present in solution according to a reversible exothermic reaction. With MEA, typically two molecules of MEA are required to absorb one molecule of CO2. More complex, sterically hindered amines, including tertiary amines, were found to provide improved stoichiometry.
A major portion of the acid compound is absorbed in the absorbent solution, and the rich absorbent solution is then routed to a regeneration step for being regenerated, usually at higher temperatures and lower pressures compared to the absorption step, typically the regenerator being a tower having a reboiler at the bottom and/or with vapour stripping, preferably steam stripping. In the regeneration step, the acid compounds are released into the vapour phase, which is separated off. After condensation and reflux of most of the water in the vapour leaving the tower, the acid compounds may become available at relatively high concentrations. The hot lean absorbent solution from the regenerator bottom is then usually cooled and recycled to the absorption step. Typically, a heat exchange between the lean absorbent solution being cooled and the rich absorbent solution being heated is included in the cycle.
A major problem with such absorption-regeneration cycle for acid compound removal is the amount of energy required, primarily for the regeneration step. The thermal energy required for the regeneration may be split in three parts linked with (i) heating of the absorbent solution between the absorption stage and the regeneration stage, i.e. the sensible heat of the absorbent solution, (ii) its vaporization heat, and (iii) the binding energy between the absorbed species and the absorbent solution.
The binding energy between the absorbed species and the absorbent solution is higher when the affinity between the solvent compounds and the acid compounds to be removed is high. It is more expensive to regenerate a very basic primary alkanolamine such as MEA than a tertiary amine such as bis(2-hydroxyethyl)-methylamine, also known as methyl diethanol amine (MDEA). Without wanting to be bound to this theory, this difference may for instance be due to that in aqueous solutions CO2 and unhindered primary and secondary amines are believed to form stable carbamate anions, while hindered tertiary amines may primarily form bicarbonate ions. This would favour tertiary amines, but other differences such as mass transfer rates and absorption kinetics may direct into the opposite direction.
The vaporisation heat of the absorbent solution is also important because the thermal regeneration step requires vaporisation of a significant fraction of the absorbent solution in order to obtain the stripping effect which favours elimination of the acid compounds from the absorbent solution. The absorbent solution fraction to be vaporised is proportional to the extent of the association between the absorbed acid compound and the absorbent solution. However, an easily vaporisable absorbent solution brings the drawback that more of the absorbent solution may be entrained in the gas stream leaving the absorber overhead, i.e. with the stream from which the acid compounds have been removed.
The sensible heat part is essentially linked to the absorption capacity of the absorbent solution. It is proportional to the flow rate of the absorbent solution being regenerated.
In this context, the search for the ideal absorbent compound has become complex, and has been concerned with a.o. the following criteria:                the selectivity towards acid compounds in relation to other compounds in the feed stream to be treated, such as hydrocarbons, hydrogen and carbon monoxide, in the case of streams such as natural gas, synthesis gas and/or refinery gasses,        the rate of absorption of the different acid compounds of interest,        the absorption capacity for the different acid compounds of interest,        as this may suggest an increase of the absorbent concentration in the absorbent solution, the solubility of the absorbent into the solvent or solvent cocktail should be sufficiently high —hence the option to also study the solvent phase —and the viscosity of the concentrated absorbent solution should remain limited, as well as its corrosive behaviour,        the heat of reaction in the absorption step, which relates to the temperature increase of the absorption solution in the absorption step and also to the heat required for again releasing the acid compound in the regeneration step, as discussed above,        thermal stability, in relation to maintaining its chemical integrity at the conditions which govern the more severe regeneration step,        low vapour pressure, in order to limit the losses of absorbent in the deacidified stream leaving the absorption step in case the feed stream to be treated is a vapour stream.CA 2861539 A1, also published as U.S. Pat. No. 8,034,166 B2, proposes to use an absorbent comprising at least one amine and at least one aminocarboxylic acid and/or aminosulfonic acid, for removing carbon dioxide from a gas stream. A wide variety of, amines is proposed, all very conventional and typically comprising at least one primary or secondary amine group. Only monoethanol amine was exemplified, each time in mixture with N,N-dimethylglycine or 2-methylalanine as the amino acid in the absorbent medium. The examples were showing the absorption of CO2 from flue gas at 1 bar absolute pressure. The objective in CA 2861539 was to reduce the steam consumption in the regeneration step.        
In search of a reduction of the energy requirement of the absorption-regeneration cycle associated with deacidification, US 2006/0104877 A1 proposes to use an absorbent solution which forms two separable liquid phases when it absorbs an amount of acid compounds, such that only the phase laden with acid compounds needs to be regenerated. The drawback of this proposal requires extra process steps above the conventional deacidification process, and therefore extra process equipment is required.
US 2009/0264180 A1 proposes a variation of this liquid phase separation concept, in which a strong acid such as phosphoric acid is added, in a process using an absorbent having at least two amine functions, in order to further enrich the liquid phase which should be regenerated with acid compounds, and to separate off unreacted reactive absorbent compounds before the regeneration. The document further suggests adding salts to the absorbent solution so as to favour the phenomenon of separation of the absorbent solution into two phases. Also here, extra process steps and associated equipment are required.
US 2009/0199709 A1 proposes an absorption solution which separates into two liquid phases when it has absorbed and amount of acid compounds and when it is heated. Again, this proposal requires extra process steps and associated equipment over and above the conventional deacidification equipment.
There therefore remains a need for an absorbent solution which exhibits excellent performance in a conventional absorption-regeneration cycle but which does not exhibit the separation into two liquid phases when being loaded with acid compounds at any of the temperatures occurring in the process cycle.
The present invention aims to obviate or at least mitigate the above described problem and/or to provide improvements generally.